1. Field of the Invention
This invention relates in general to oil and gas flow production, and in particular to a system for removal of accumulated liquid from gas producing wells.
2. Description of the Prior Art
Many gas wells produce both gas and liquid such as water, oil, and condensate. The gas is often flowed from the casing to a sales line or offtake line at the surface. Part of the liquid, initially entrained as droplets in gas flow, may drop out of the flow because of insufficient velocity of gas. The liquid can accumulate in the bottom of the well or near the bottom of the producing formation. As accumulation increases, it can exert an increasingly large back pressure on the formation. This back pressure, which equals the hydrostatic head of the liquid column, may be large enough to reduce the production rate of the gas well or even completely stop production.
It is therefore highly advantageous to remove liquids from gas wells so as to prevent such accumulation in the wellbore and consequent back pressure on the producing formation.
The prior art has taken various approaches to removing such gas well liquids which exert back pressure on a producing formation. A brief description of the state of the art is provided in "A Practical Approach to Removing Gas Well Liquids", Edward J. Hutlas and William R. Granberry, Journal of Petroleum Technology, August, 1972, pages 916-922. Sometimes wells are blown periodically to remove liquids along with the thus very rapidly produced gas. Often times, siphon strings or velocity tubes are run and the pumper unloads the liquids from the wells from time to time by opening such siphon strings or velocity tubes to atmospheric pressure; thus blowing liquids from near the bottom of the well. Sometimes small holes are drilled in the siphon strings to aid in lifting the liquids. These "weepholes" enable gas to enter into the tubing at intervals uphole, providing additional lift toward the surface, a gas lift effect. Time clock intermitters and differential pressure intermitters are also often used as disclosed in the article. Pumps and combination liquid diverter and gas lift installations are also often used as is described in the article.
U.S. Pat. No. 4,275,790 discloses another approach wherein the well has a tubing string located inside the casing, with the tubing in contact with the accumulated liquid. Both the tubing and the casing are connected to the sales line or offtake line. Periodically, both the casing and tubing are shut in, allowing formation pressure to build up in the casing. Then the tubing is opened to the sales line to discharge accumulated liquid, it being driven by the higher formation pressure that has built up.
U.S. Pat. No. 4,509,599 discloses a system wherein a compressor is employed to pump gas from a tubing string pathway disposed in a gas well to a gas pathway which runs up the annulus, thus unloading liquids from near the bottom of the well via the tubing pathway.
U.S. Pat. No. 3,863,714 discloses an automatic gas well control device which optimizes gas well production by allowing the well to produce only while adequate flow rates are maintained. The device includes a control valve and discharge line which is responsive to the pressure differential between the tubing and sales line and to the rate of discharge from the well as measured by differential pilot valves. One pilot valve sends a pneumatic signal to close the control valve when the rate of production drops below a predetermined level to thus shut in the well and permit gas pressure to build to a sufficient level for acceptable production. Another pilot valve monitors sales and tubing line pressure and operates to send a signal to the control valve to open the control valve only when the tubing pressure exceeds the sales line pressure by a predetermined differential.
Thus, since natural gas fills a growing percentage of our nations energy requirements due to its availability, relatively low price, and clean burning qualities, and since deliverabilities of gas wells decline over time and discovery of new gas reservoirs becomes more difficult, it is needed to maximize gas recovery from every gas well, so that gas supplies are not left untapped.
As pointed in the article by Hutlas and Granberry, the primary disadvantage that has limited wider utilization of smaller tubing strings as a solution to the liquid build up is the associated pressure drop caused at higher flow rates through relatively small diameter tubing string. Although ideal for gas wells near the end of their producing life (many old wells are being retrofitted with smaller tubing everyday), a smaller tubing would be too restrictive to produce wells at their maximum capabilities early in their producing life.
As is pointed out in SPE 11583 "Gas Well Operation With Liquid Production", J. F. Lea and R. E. Tighe, other methods for minimizing liquid loading are available. Well head compression, plunger lift, siphon strings, rotative gas lift, and foaming agents are known. These other methods all have disadvantages, primarily higher operating costs and maintenance requirements. The basic problem has been that for a given gas flow rate, there are only a limited range of tubing diameters that ensure adequate velocity to remove liquids, yet are not overly restrictive to flow. As gas well deliverability declines and the flow rates decrease, smaller tubing is needed. Since it is not practical nor economical to change tubing size every few years, the above other methods of liquid unloading have been subsequentially developed. There is still a great need for improved methods of liquid unloading, and the invention at hand addresses that need.
The invention at hand eliminates the flow restriction caused by smaller tubing. This allows small tubing to be installed in any gas well, eliminating liquid loading problems for almost the entire producing life of a gas well. The benefits of this are higher ultimate recovery, less well supervision, and stabilized flow rates. Smaller tubing installed upon initial well completion, is likely to be less costly than the larger tubing sizes normally employed. The smaller tubing also eliminates the need to expend capital and manpower needed for the other methods for removing liquids.